The present invention relates to earth-penetrating drill bits, and particularly to fixed-cutter rotating bits such as are used for drilling oil and gas wells.
Background: Rotary Drilling
Oil wells and gas wells are drilled by a process of rotary drilling. In conventional vertical drilling a drill bit is mounted on the end of a drill string (drill pipe plus drill collars), which may be several miles long. At the surface a rotary drive turns the string, including the bit at the bottom of the hole, while drilling fluid (or xe2x80x9cmudxe2x80x9d) is pumped through the string.
When the bit wears out or breaks during drilling, it must be brought up out of the hole. This requires a process called xe2x80x9ctrippingxe2x80x9d: a heavy hoist pulls the entire drill string out of the hole, in stages of (for example) about ninety feet at a time. After each stage of lifting, one xe2x80x9cstandxe2x80x9d of pipe is unscrewed and laid aside for reassembly (while the weight of the drill string is temporarily supported by another mechanism). Since the total weight of the drill string may be hundreds of tons, and the length of the drill string may be tens of thousands of feet, this is not a trivial job. One trip can require tens of hours, and this is a significant expense in the drilling budget. To resume drilling the entire process must be reversed. The bit""s durability is very important, to minimize round trips for bit replacement during drilling.
The simplest type of bit is a xe2x80x9cdragxe2x80x9d bit (or xe2x80x9cfixed-cutterxe2x80x9d bit), where the entire bit rotates as a single unit. The body of the bit holds fixed teeth, which are typically made of an extremely hard material, such as e.g. tungsten carbide faced with polycrystalline diamond compact (PDC). The body of the bit may be steel, or may be a matrix of a harder material such as tungsten carbide. FIG. 1C shows an exemplary fixed cutter drill bit.
Fixed-cutter bits have undergone a dramatic development in the past decade. Originally PDC-type bits were used for cutting only a limited set of fairly soft formations, but their performance was so good (in appropriate applications) that there has been steady pressure to use them in an increasing range of formations. At the same time the technology of the ultrahard compacts has steadily advanced, as the metallurgy of diamond-loaded cermets has become better understood. The resistance of modern compacts to abrasion is very good, but fracturing is still a limiting factor.
As the drillstring is turned, the teeth of the drag bit are pushed through the rock by the combined forces of the weight-on-bit and the torque seen at the bit. (The torque at the bit will be somewhat less than the rotary or top drive torque, due to drag along the length of the drill string. The torque at the bit may also contain a dynamic component due to oscillation modes of the drill string). Since the weight-on-bit and the rotary torque are controlled by the driller, the net thrust vector seen at the tooth face will be slightly uncertain; but the normal range of torque and WOB values will imply only a relatively small range of angular uncertainty for each tooth""s net force vector. (The rate-of-penetration and the hardness of the formation also have some effect on the orientation of the thrust vector seen at the tooth.) Thus each tooth can be aligned to an expected thrust direction, within a cone of a few degrees of uncertainty.
The individual elements of a drill string appear heavy and rigid. However, in the complete drill string (which can be more than a mile long), the individual elements are quite flexible enough to allow oscillation at frequencies near the rotary speed. In fact, many different modes of oscillation are possible. (A simple demonstration of modes of oscillation can be done by twirling a piece of rope or chain: the rope can be twirled in a flat slow circle, or, at faster speeds, so that it appears to cross itself one or more times.) The drill string is actually a much more complex system than a hanging rope, and can oscillate in many different ways; see WAVE PROPAGATION IN PETROLEUM ENGINEERING, Wilson C. Chin, (1994).
The oscillations are damped somewhat by the drilling mud, or by friction where the drill pipe rubs against the walls, or by the energy absorbed in fracturing the formation: but often these sources of damping are not enough to prevent oscillation. Since these oscillations occur down in the wellbore, they can be hard to detect, but they are generally undesirable. Drill string oscillations change the instantaneous force on the bit, and that means that the bit will not operate as designed. For example, the bit may drill oversize, or off-center, or may wear out much sooner than expected. Oscillations are hard to predict, since different mechanical forces can combine to produce xe2x80x9ccoupled modesxe2x80x9d; the problems of gyration and whirl are an example of this. These dynamic instabilities can severely degrade drilling performance, and may not be easy to detect from the surface. Moreover, the rock failure process inherently generates stick-slip vibrations to excite dynamic modes.
The other common bit type is the rotary cone (or xe2x80x9croller-conexe2x80x9d) bit, in which the bore face is cut by rotating elements (which usually have a roughly conical shape), bearing machined or inserted teeth. FIG. 1B shows an example of such a bit.
Background: Transitional Formations
In interbedded xe2x80x9ctransitionalxe2x80x9d formations rock strength can change significantly over a bit length. The present inventors have realized that this is an important factor in the lifetime of fixed-cutter drill bits.
If the overloaded cutter fails, the cutter which follows it will be even more overloaded, and is also likely to fail. Similarly, if any of the frontal area of this cutter is lost to spalling or fracturing, following cutters may be overloaded.
Transition-Optimized Cutter Torque Distribution
The present invention teaches that the forces which appear on the individual cutting elements of a drill bit should be evenly distributed, as far as possible, under transitional conditions as well as under steady-state conditions. Thus when the drill bit drills into a layer of harder or softer rock, the chances of an individual cutter receiving a disproportionate load, and possibly breaking, are greatly reduced. Thus in the preferred embodiment cutter loadings are simulated during a transition into harder rock, and in alternative embodiments cutter loadings can be simulated both during transition to harder rock and during transition to softer rock.
The disclosed innovations, in various embodiments, provide one or more of at least the following advantages:
Improved bit life
Improved cutter life in transitional formations
Lower Repair Cost
Improved ROP
More consistently reliable minimum bit life
Reduced susceptibility to dynamic instabilities.